1. Field of the Invention
The present invention relates generally to oilfield operations. More particularly, the present invention pertains to systems and methods for monitoring downhole conditions in wellbores, including fluid characteristics and formation parameters, using sensors, gauges and other instrumentation.
2. Description of the Related Art
During the life of a producing hydrocarbon well or an injection well, it is sometimes desirable to monitor conditions in situ. Recently, technology has enabled well operators to monitor conditions within a wellbore by installing permanent monitoring systems downhole. The monitoring systems permit the operator to monitor multiphase fluid flow, as well as pressure and temperature. Downhole measurements of pressure, temperature and fluid flow play an important role in managing oil and gas or other sub-surface reservoirs.
Historically, permanent monitoring systems have used electronic components to provide pressure, temperature, flow rate and water fraction on a real-time basis. These monitoring systems employ temperature gauges, pressure gauges, acoustic sensors, and other instruments, or “sondes,” disposed within the wellbore. Such instruments are either battery operated, or are powered by electrical cables deployed from the surface.
Historically, the monitoring systems have been configured to provide an electrical line that allows the measuring instruments, or sensors, to send measurements to the surface. Recently, fiber optic sensors have been developed which communicate readings from the wellbore to optical signal processing equipment located at the surface. The fiber optic sensors may be variably located within the wellbore. For example, optical sensors may be positioned to be in fluid communication with the housing of a submersible electrical pump. Such an arrangement is taught in U.S. Pat. No. 5,892,860, issued to Maron, et al., in 1999. The '860 patent is incorporated herein in its entirety, by reference. Fiber optic sensors may also be disposed along the tubing within a wellbore. In either instance, a fiber optic cable is run from the surface to the sensing apparatus downhole. The fiber optic cable transmits optical signals to an optical signal processor at the surface.
FIG. 1 presents a cross-section of a wellbore 50 which has been completed for the production/injection of effluents. The wellbore 50 extends downward into an earth formation 55. It can be seen that the wellbore 50 has a string of casing 15 that has been cemented into place. A column of cement 20 is cured between the casing string 15 and the earth formation 55. It can also be seen that a liner string 30 has been hung off of the casing 15 and extends into the pay zone. One or more intermediate strings of casing 15′ are optionally deployed between the initial string of casing 15 and the lowest liner 30. At its lower end, the liner string 30 is perforated. Perforations 35 provide fluid communication between the earth formation 55 and the internal bore of the liner 30. Alternatively, the wellbore 50 may be completed as an open hole.
Also visible in the wellbore 50 of FIG. 1 is a tubing string 35. The tubing string 35 may be a production string or an injection string. The tubing string 55 extends from the surface to the pay zone depth. The tubing string 35 is hung from a surface assembly, shown schematically at 60. An example of such a surface assembly 60 is a production assembly for receiving hydrocarbons. A packer 40 is shown affixed to the tubing string 35 so as to seal off the annular region between the tubing string 35 and the surrounding liner 30. In this way, production fluids are directed to the surface production assembly 60.
The wellbore 50 of FIG. 1 also includes a submersible electrical pump 45. The pump 45 is disposed at the lower end of the tubing 35. The pump 45 may be an electrical submersible pump, or may be driven mechanically by sucker rods (not shown). The pump 45 serves as an artificial lift mechanism, driving production fluids from the bottom of the wellbore 50 to the surface assembly 60. Of course, it is understood that the formation 55 may be able to produce without artificial lifting means.
The wellbore 50 of FIG. 1 has a downhole monitoring system 100 positioned therein. The monitoring system 100 is designed to operate through one or more sensors connected to a cable 136. An example of such a sensor is a fiber optic sensor. The sensor is positioned within a tubular side mandrel, shown schematically at 110. It can be seen that the mandrel 110 is disposed in series with the tubing string 35 above or below the packer 40. The mandrel is configured to hold one or more sensors (shown more fully at 10 in FIG. 2). More specifically, the mandrel 110 includes a side pocket (shown at 112 in FIG. 2). The sensor 10 may define a pressure gauge, a temperature gauge, an acoustic sensor, or other sondes. The sensor may be either electrical or fiber optic.
FIG. 2 presents an enlarged cutaway view of the tubular side mandrel 110. The mandrel 110 has a lower end 116 and an upper end 118. The lower end 116 defines a male pin, while the upper end 118 defines a female collar. Each end 116, 118 is arranged to threadedly connect to a respective joint of tubing 55 (not shown in FIG. 2). A clamp 120 is placed around the mandrel 110. The clamp 120 is provided to hold one or more cables 136. In one example, the cable 136 is a fiber optic cable.
As noted, the mandrel 110 includes a side pocket 112. The side pocket 112 defines an eccentric portion extending to a side of the mandrel 110. The side pocket 112 houses the sensor 10. In the arrangement of FIG. 2, the sensor 10 is further held within the side pocket 112 by a separate gauge housing 114 having a port 115 to provide hydraulic communication between the main bore of the mandrel 110 and the sensor 10.
The sensor 10 is in optical communication with the optical cable 136. The cable 136 extends through openings (not shown) in the mandrel side pocket 112 and the gauge housing 114. In the fuller wellbore view of FIG. 1, it can be seen that the optical cable 136 extends upward from the sensor 10 within the mandrel 110, to the surface. In the example of FIG. 1, the cable 136 connects to optical signal processing equipment 132 that is located at the surface of the wellbore 50. The optical signal processing equipment 132 includes an excitation light source, shown schematically at 134. Excitation light may be provided by a broadband light source 134, such as a light emitting diode (LED) located within the optical signal processing equipment 132. The optical signal processing equipment 132 will also include appropriate equipment for delivery of signal light to the sensor(s) 10, e.g., Bragg gratings and a pressure gauge. Additionally, the optical signal processing equipment 132 includes appropriate optical signal analysis equipment for analyzing the return signals from the Bragg gratings (not shown).
The fiber optic cable 136 is not shown in cross-section. However, it is understood that where the cable 136 is a fiber optic cable, it will be designed so as to deliver pulses of optic energy from the light source 134 to the sensor(s) 10. The fiber optic cable 136 is also designed to withstand the high temperatures and pressures prevailing within a hydrocarbon wellbore 50. Preferably, the fiber optic cable 136 includes an internal optical fiber (not shown) which is protected from mechanical and environmental damage by a surrounding capillary tube (also not shown). The capillary tube is made of a high strength, rigid-walled, corrosion-resistant material, such as stainless steel. The tube is attached to the sensor 10 by appropriate means, such as threads, a weld, or other suitable method. The optical fiber 12 contains a light guiding core (not shown) which guides light along the fiber. The core preferably employs one or more Bragg gratings to act as a resonant cavity and to also interact with the sonde 10.
Construction and operation of a fiber optic sensor 10, in one embodiment, is described in the '860 patent, mentioned above. In that patent, it is explained that each Bragg grating is constructed so as to reflect a particular wavelength or frequency of light being propagating along the core, back in the direction of the light source from which it was launched. Each of the particular frequencies is different from the other, such that each Bragg grating reflects a unique frequency.
Returning to FIG. 2, it can be seen that the configuration of the prior art mandrel 110 involved an eccentric design which incorporates a side pocket 112. The use of the side pocket 112 requires that the OD of the mandrel 110 be increased so as to accommodate the geometry of the side pocket 112. Furthermore the conventional mandrel/sensor systems have several potential leak paths between the tubing 55 and the surrounding liner 30. Therefore, a new design is needed for a tool to house sensing instrumentation. There is also a need for a sensing apparatus that decreases the possibility of leaks by reducing leak paths. Further, there is a need for a sub that more easily conforms to the dimensions of the surrounding liner and does not unduly restrict the flow of fluids therethrough.